Fluid characterization is very important to the assessment of economic viability for a hydrocarbon-bearing reservoir formation. Some wireline tools such as Schlumberger's MDT (Modular Dynamic Tester) are used to sample formation fluids, store it in a set of bottles, and retrieve it to surface while keeping the fluid pressurized. Such samples. are known as live fluids. These live fluids are then sent to an appropriate laboratory to be characterized. Characterization of the fluids may include composition analysis, fluid properties and phase behavior.
Understanding reservoir fluid phase behavior is key to proper planning and development of the respective fields and design of the production system. Understanding reservoir fluid phase behavior involves conducting a number of very important measurements on the fluid at realistic reservoir and production conditions. In most cases, changes in temperature (T) and pressure (P) of the formation fluid lead to phase changes, including phase separation (e.g., liquid-vapor, liquid-solid, liquid-liquid, vapor-liquid etc.), and phase recombination. For example, while most hydrocarbons exist as a single phase at initial reservoir conditions (i.e., composition, pressure, and temperature), they often undergo reversible (and possibly some irreversible) multi-phase changes due to pressure, composition and/or temperature reduction during production and flow to the surface facilities. FIG. 1 illustrates a typical phase diagram measured for an under-saturated live oil prone to precipitate asphaltene, wax, and hydrate during production.
Liquid-Solid-Vapor phase boundaries are typically measured at a laboratory using state-of-the-art-technologies, such as Schlumberger's pressure-volume-temperature (PVT) unit coupled to Schlumberger's laser-based Solids Detection System (SDS) and Schlumberger's high-pressure microscope (HPM). Detailed descriptions of these state-of-the art technologies and their applications for the study of phase behavior and flow assurance of petroleum fluids have been published and are known to those of skill in the art.
The HPM is currently used in a laboratory environment to characterize formation fluids. FIGS. 2a-2b illustrate examples of an HPM study with snapshots of a fluid before and after a phase transition point:                FIG. 2a shows an example of asphaltene onset pressure measurement at reservoir temperature (Tres).        FIG. 2b shows the formation of liquid-liquid split above the saturation pressure of a reservoir fluid at Tres.        
The HPM (typically equipped with a cross polarizer) makes it possible to quantify particle or bubble size. Moreover, it is possible to make a clear distinction between wax, asphaltene, oil phase, water droplets, and hydrate crystals when the multiple components are coexisting as evidenced in FIG. 2-c and 2-d. 
However, the current trend in the wireline industry is to perform more and more analysis of the formation fluid properties directly downhole to avoid the difficulties associated with sample preservation when lifted uphole and delays associated with sample transportation and analysis in a remote laboratory. Tools like Schlumberger's MDT can, for example, be retrofitted with a spectrometer module such as a Live Fluid Analyser or Gas Condensate Analyser in order to provide basic information on the fluid composition (Gas-to-oil ratio (GOR), water content, basic crackdown of hydrocarbon fractions (C1, C2-C5, C6+)). These measurements are performed by infrared (IR) absorption spectroscopy. FIG. 3 presents a typical absorption spectrum of a typical oil and of other species present in the oil, such as water. Characteristic absorption peaks can therefore be measured, especially in the near IR (NIR) range.
Nevertheless, current measurements of certain downhole characteristics such as phase behavior are not available outside of a laboratory. Video image fluid characterization is currently only available in laboratory environments as described above, yet it is desirable to analyze formations fluids in situ.
There has been some use of video imaging downhole in wireline tools, but current technology is limited to applications related to production logging. Current downhole imaging is dedicated to borehole wall imaging and has low spatial resolution. DHV International, for example, provides downhole video services to the oil and gas industry for diagnosis of borehole problems such as fishing out lost tools, mechanical inspection, and fluid entry surveys. There are currently no methods or systems for fully characterizing formation fluids downhole.
In addition to characterizing formation fluids at well assessment stages, the understanding of phase behavior is also extremely important during the production phase of well operations. As mentioned above, during production, the formation fluids cool down and depressurize as they travel from the reservoir to the surface. The fluids can undergo several phase changes that are currently not very well understood. These phase changes can lead to serious problems, especially if a solid phase precipitate (such as wax or asphaltene) forms. In certain conditions, these solids can stick to wall casing, forming a solid deposit and eventually decrease well productivity by increasing the resistance to flow (reduced hydraulic diameter of the tubing) or build-up a plug. Similar problems can especially take place in a subsea environment along the pipelines used to carry oil from a production well to onshore environments.
Accordingly, the introduction of phase behavior monitoring downhole during production would be a significant breakthrough in order to optimize production conditions and reduce/control the risk of solid phase precipitation and, in turn, deposition.
The present invention is direct to overcoming, or at least reducing the effects of, one or more of the problems presented above.